Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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A METHOD AND AN APPARATUS FOR RETRIEVING A TUBING FROM A WELL
This invention relates to a method and an apparatus for retrieving a tubing
from a
well. More specifically, the invention relates to the removal of tubular from
wells
associated with the production of hydrocarbons.
When wells are permanently plugged and abandoned, well tubular such as the
production tubing and casing may have to be pulled out of the well. In areas
such as
the North Sea, wells may be deep and completed with relatively large dimension
pipe.
Consequently, the cumulative weight of tubing and/or casing may become very
high,
requiring heavy duty lifting/pulling equipment to retrieve it from the well.
In some cases, wells to be permanently plugged and abandoned are located
onboard
old platforms where the original drilling equipment in place has been removed.
Traditionally, for such cases, drilling rigs such as jack-up rigs has to be
mobilized to
pull the relevant tubular out of the well, entailing a substantial cost.
Similar
considerations apply for subsea wells, where floating drilling rigs have to be
mobilized
for plug and abandonment operations to retrieve tubing and casing from the
wells.
On platforms, as an alternative to mobilizing rigs, tubular jack systems have
been
developed for this purpose. Despite being a significant improvement compared
to rig
mobilization what costs regard, tubing jacking systems may still encompass
relatively
bulky and expensive equipment modules.
Besides the equipment required for the pulling of tubing/casing, associated
steps of an
abandonment process may comprise various wireline operations, fluid pumping
operations as well as the placement of cement plugs using coil tubing.
Altogether, the
combination of all these services might yield a bulky and expensive equipment
package.
A common feature with most known systems and methods related to tubing and
casing retrieval is that they are designed and dimensioned for pulling very
high
2
weight, and that an operation is normally conducted by cutting the tubular
deep
in the well, and then retrieving it to the surface in one go.
For subsea wells, subsea located tubular jack systems have been
conceptualized.
No commercial system has been made as of yet, but may be under development.
Besides systems developed to pull the tubing from surface, there exists one
known system for jacking tubular in the underground. The system features
double anchor modules and a hydraulic actuator, operated on drill pipe,
snubbing
pipe or coil tubing, and is typically used to release piping that is stuck in
the well.
Here, rather than pulling (and/or jarring) from surface, the jack is engaged
to the
pipe that is stuck by means of a first anchoring module, whereupon a second
anchoring module is engaged to a different mechanical reference point,
typically
the casing, whereupon the actuator is operated to jack the stuck pipe segment
loose. The use of downhole jacks is very practical to release stuck piping,
but
considered to be impractical for traditional tubing/casing retrieval as the
.. operation would be very time consuming.
The object of the invention is to provide for a system and method for
retrieving
tubular from a well that is more time and cost efficient than current systems
and
methods. Moreover, it is an objective of the invention to provide for a system
that
requires less pulling (and/or pushing) force than what is the situation with
the
current art methods, so that heavy duty pipe retrieval equipment can be
replaced
by lighter equipment. Thus, the present invention provides for the retrieval
of
well tubular by means of lighter well servicing techniques such as wireline
and/or
coil tubing.
According to a first aspect of the present invention there is provided a
method for
retrieving a tubing from a well at least partly filled with a liquid, the
tubing having
a first end portion and a second end portion, wherein the method comprising
the
steps of:
- running a retrieval apparatus using a connecting means from a surface and
into
the well, the retrieval apparatus comprising:
- an engagement means for engaging the tubing;
- a sealing means for sealing a portion of the bore of the tubing;
- injection means for injecting a low density fluid into the tubing,
- connecting the engagement means to a portion of the tubing;
- activating the sealing means to close liquid communication in the bore of
the
tubing
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between the first end portion and the second end portion;
- replacing at least a portion of a volume of liquid by a low density fluid
introduced in
said volume by the injection means; and
- retrieving the tubing out of the well using the connecting means.
The volume of liquid to be replaced may be defined by the sealing means, the
tubing
and the second end portion of the tubing. Thus, the low density fluid is
injected
directly into the liquid.
The sealing means may comprise an inflatable bladder arranged to be filled
with the
low density fluid so that the low density fluid replaces the volume of liquid
by
increasing the volume of the bladder.
The low density fluid may be supplied from the surface of the well through a
line
extending from the surface to the apparatus.
In an alternative embodiment, the low density fluid may be supplied from a
vessel
operable to communicate low density fluid to the injection means, the vessel
being
arranged between the apparatus and the surface of the well.
In still another alternative embodiment, the low density fluid is supplied
from both the
surface of the well and from the vessel.
The buoyancy of the tubing may be controlled during retrieval by replacing a
volume
of the low density fluid in the tubing by a liquid.
In one embodiment a packer is introduced in the bore of the tubing between the
sealing means and the second end portion of the tubing. Thus, a chamber
defined by
the sealing means, the packer and the wall of the tubes is provided. In a
preferred
embodiment the chamber is provided with a valve arrangement such as a check
valve
that allows for one-way flow of fluid out of the chamber.
According to a second aspect of the present invention there is provided an
apparatus
for retrieving a tubing from a well at least partly filled with a liquid, the
tubing having
a first end portion and a second end portion, wherein the apparatus
comprising:
- an engagement means for engaging the tubing;
- a sealing means for sealing a portion of the bore of the tubing;
- injection means for injecting a low density fluid into the tubing in or at
an elevation
below, the sealing means; and
- connecting means to a surface of the well.
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The sealing means may comprise an inflatable bladder for receiving low density
fluid
injected by the injections means. In such an embodiment the low density fluid
is
injected into the tubing via the inflatable bladder, so that the low density
fluid replaces
the volume of liquid by increasing the volume of the bladder.
Alternatively, the low density fluid is injected directly into the liquid in
the tubing at an
elevation below the sealing means.
The apparatus may further comprise a control module comprising one or a
combination of; means for controlling the engagement means; means for
controlling
the sealing means; one or more sensor means selected from of the group
comprising:
pressure sensor, temperature sensor, acceleration sensor, velocity sensor.
The control module may further be provided with at least one valve for
communicating
a fluid into or out of the tubing.
The control module may further comprise means for disconnecting the connecting
means from the apparatus.
In one embodiment the apparatus is further provided with a pumping device
arranged
for evacuating a liquid contained between the sealing means and a packer
arranged in
the bore of the tubing between the sealing means and the second end portion of
the
tubing.
A third aspect of the present invention regards use of a low density fluid for
increasing
buoyancy of a tubing in a well at least partly filled with a liquid, and
thereby
facilitating retrieval of the tubing from the well.
Although a low density fluid in the form of a gas is preferred for increasing
the
buoyancy of the tubing, the low density fluid may also be a liquid having a
lower
density than the heavy fluid to be replaced. Thus, a condensate or even water
may be
used, for example. However, in the description below the low density fluid
will be
referred to as gas, but should not exclude other appropriate fluids having a
density
lower than the heavy fluid to be replaced.
The following describes a non-limiting example of a preferred embodiment
illustrated
in the accompanying drawings, in which:
Fig. 1 illustrates a prior art top section of a well and a unihead;
Fig. 2 illustrates in a larger scale a prior art bottom section of a
well;
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Fig. 3 illustrates prior art permanent barriers installed in a well;
Fig. 4 illustrates in a smaller scale an initial step of preparing for
retrieval of a
tubing from a well;
Fig. 5 illustrates in a larger scale a further step of preparing for
retrieval of the
tubing;
Fig. 6-8 illustrates further prior art steps of preparing for retrieval of
the tubing;
Fig. 9 illustrates a prior art working platform for personnel and a
wireline rig-up
mast;
Fig. 10 illustrates a prior art a crane system mounted on skid beams, the
system
including a pipe handling apparatus;
Fig. 11 illustrates in a larger scale a section of a well comprising a
tubular within
a casing filled with a liquid;
Fig. 12 illustrates the well in fig. 11, where a cutting tool is used for
cutting a
lower portion of the tubular;
Fig. 13 illustrates the well in fig. 12, but after the cutting tool has
been removed
and a barrier has been set in a lower portion of the tubular;
Fig. 14 illustrates a tubing retrieval apparatus according to the present
invention
connected to a top portion of the tubing in figures 11-13;
Fig. 15 illustrates the same as fig. 14, but after the apparatus has
started filling
the tubular with a low density fluid in the form of a gas;
Fig. 16 illustrates retrieval of the tubular filled with gas and the
liquid is displaced
out of the tubular;
Fig. 17 illustrates in a larger scale parts of a surface pressure control
equipment
for one embodiment of the invention;
Fig. 18 illustrates a step of physical disassembly and removal of the
tubing when
this has reached the surface;
Fig. 19 illustrates a lifting device lifting the tubing out of the well;
Fig. 20 illustrates a situation where the tubing is stuck in the well;
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Fig. 21 illustrates a step where the apparatus according to the present
invention
is used for releasing the stuck tubing;
Fig. 22 illustrates the same as fig. 15 with an alternative embodiment of
the
apparatus according to the present invention;
Fig. 23 illustrates the same as fig. 15 in an alternative embodiment where
the
apparatus is connected to a coil tubing;
Fig. 24 illustrates the same as fig. 15 in an alternative embodiment
where the
apparatus is connected to a wireline comprising a hydraulic line;
Fig. 25a illustrates a cross section of one embodiment of the wireline in
fig. 24;
Fig. 25b illustrates a cross section of one embodiment of the wireline in
fig. 24;
Fig. 26 illustrates an alternative embodiment of the apparatus shown in
fig. 15;
Fig. 27 illustrates an embodiment where the apparatus is engaged to the
tubing
about halfway between the first end portion and the second end portion
and not at the first end portion as illustrated e.g. in fig. 14; and
Fig. 28 illustrates an embodiment where the sealing means comprises an
inflatable bladder, wherein the bladder replaced the liquid in the tubing as
the volume of the bladder is increased by the gas.
In the figures, similar or corresponding parts may be indicated by the same
reference
numerals.
Position indications such as e.g. upper, lower, above, below, and also
directions such
as upwards and downwards, refer to the position shown in the figures.
Fig. 1 illustrates a top section of a well 100 and a unihead 101 as will be
known by a
person skilled in the art. The unihead 101 is the common term for the top
section of a
well 100 where the different well tubular are fixed to the surface system of
the well. A
main surface valve block, often referred to as x-mas tree 102, including a
bore routing
the well production to flow lines and separators, is indicated in the top of
fig. 1.
Various common casing and tubular are shown, starting with a conductor casing
103,
a surface casing 104 that is cemented to a formation surrounding the well and
to the
conductor casing 103 with a cement layer 105, an intermediate casing 106 being
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cemented to the formation by a cement layer 105', a production casing 107 and
a
production tubing 108.
Some distance below the unihead 101, the production tubing 108 comprises a
downhole safety valve 109. The downhole safety valve is operated by means of a
hydraulic control line 110.
The surface casing 104 is suspended from a lower portion 111 of the unihead
101. The
intermediate casing 106 is terminated in an intermediate casing hanger 112
that is
suspended in the lower portion 111 of the unihead 101. The lower unihead
portion 111
is connected to an intermediate unihead portion 113 by means of a clamp 114.
The production casing 107 is terminated in a production casing hanger 115
suspended
from the intermediate unihead portion 113. The production tubing 108 is
terminated in
a tubing hanger 116 suspended from a top end of the intermediate unihead
portion
113. A top portion 117 of the unihead 101 forms the connection towards the x-
mas
tree 102.
Bolts 118/118' are used to hold the upper modules attached as illustrated in
fig. 1.
The control line 110 is terminated to and exits the top portion 117 at a
termination
point 119 from where it runs to a dedicated safety valve control system (not
illustrated). Flow lines 120, 120', 120" are connected to the various annuli
between
the well tubular, to allow for fluid communication such as bleeding off
pressure, or
pump fluids into the annuli. The wellhead deck level 121' is also indicated.
Fig. 2 illustrates a bottom section of a well 100. In the example shown in
fig. 2, the
production tubing 108 includes a production packer 201 system that anchors the
tubing 108 to and forms a seal against the production casing 107. A production
liner
202 is anchored to and forms a seal against the production casing 107 by means
of a
liner hanger 203. The liner 202 extends through a hydrocarbon bearing
formation 204.
In fig. 2 the production casing 107 extends to a location above the top of the
hydrocarbon bearing formation 204, whereupon cement 105" is applied to seal
off the
annular cavity against the surrounding rock formation. In a similar manner,
the liner
202 is attached to the surrounding rock formation, including the hydrocarbon
bearing
layer 204 using cement 105". Perforations 205 provide for fluid communication
between the hydrocarbon bearing formation 204 and the center conduits of the
well
100. Although the cement 105", 105" provides a fixing means for the relevant
tubular
in the well, the most important function is that the cement 105", 105" forms a
seal in
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the annular cavity between the surrounding rock formation and the tubular in
question.
The exact construction of a well may vary significantly from what is
illustrated herein,
including a range of additional components and/or control lines as would be
appreciated by a person skilled in the art. The same applies for the unihead
101,
which may be of a significantly different design and/or contain other and/or
more
components than what is illustrated herein.
In order to deem a barrier suitable for permanent abandonment purposes,
regulations
dictate certain requirements that must be adhered to. In general terms,
permanent
barriers must be of a certain quality; they must fill the entire cross section
of the well,
including all annuli, and be of a certain minimum length.
Fig. 3 illustrates examples of permanent barriers installed in a well where a
primary
barrier 301 is installed in the lower section of the well 100 by means of
placing a
primary cement plug 3000. For the barrier 301 to be approved as a permanent
barrier, the following general requirements apply:
= The primary cement plug 3000 must overlap with the external cement 105"
on
the outside of the liner 202 over a length as specified by relevant regulatory
clauses.
= The cement 105¨ on the outside of the liner 202 must be of a certain
minimum
length (further to the requirement discussed above), and also of a specific
quality.
For permanent abandonment, regulations in most parts of the world state that
there
should be two barriers between a hydrocarbon bearing formation 204 and the
surface.
To achieve this, a secondary barrier 302 is installed in the well. In some
cases this can
be achieved by installing a cement retainer 303 (typically a mechanical plug),
and
punch holes 304 to provide for fluid communication between the center of the
tubing
108 and the annulus between the tubing and the production casing 107, prior to
placing the secondary cement plug 3001. Techniques for placement of cement
plugs
are known to a person skilled in the art and not described any further herein.
The latter method for installing a permanent well barrier could for instance
be
acceptable if the cement 105" outside the production casing 107 was verified
to be of
a sufficient length and quality, and that there were no control lines or
similar attached
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to the tubing 108 (no control line is shown in fig. 3, but regulations
prohibit leaving
such inside a permanent cement barrier).
In many cases, there is uncertainty whether the cement 105" column on the
outside
of the production casing 107 is of satisfactory length and quality. In such
cases, it may
be necessary to run logging tools to investigate on the status of the cement
in
question. In worst case, the cement 105" column behind the production casing
107 is
missing or of insufficient quality to provide a permanent barrier and the old
cement
has to be removed (or the annulus has to be cleaned) over an interval equal to
the
required length of the permanent barrier to be installed. There are various
techniques
for achieving this, ranging from section milling and under-reaming operations
to more
modern techniques involving perforating the casing 107 and using special types
of
washing tools to remove the poor cement (or clean the annulus). Such
techniques
would be known and appreciated by a person skilled in the art and no further
referred
to herein.
Both for the case where old cement 105" behind casing 107 needs to be logged,
as
well as for the situations where the cement 105" needs to be removed, the
tubing 108
must be removed before such operations can start.
The need for tubing 108 removal during a plug and abandonment job introduces
the
need for heavy lifting equipment, which complicates the operation and makes it
very
expensive.
Fig. 4 illustrates an initial step in the process of preparing for retrieval
of the tubing
108. Prior to the step illustrated in fig. 4, a variety of preparatory
operations may
have been performed, such as a wireline drift run, a wireline run to install a
deep set
mechanical barrier, punching of the tubing 108 and placement of heavy fluid in
the
tubing 108 as well as the annulus between the tubing and the production casing
107
and more. This would be appreciated by a person skilled in the art and is no
further
referred to herein.
Fig. 4 illustrates a shallow set barrier 401 such as a back pressure valve
(BPV)
installed in the top section of the well 100. In most generic cases, there
would now be
a sufficient number of barriers in place to allow for removing the x-mas tree
102
(shown in fig. 1) and install a riser 402 and BOP system required to perform
the
subsequent operational steps. Do note that a there is a distinction between
the term
"barrier" and "permanent barrier". For instance, a mechanical plug may be a
fully
accepted barrier for short term operations, but not accepted as a permanent
barrier as
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its steel components may corrode and elastomeric components may deteriorate
over
time. Bolts 403 are used to attach the riser 402 to the intermediate unihead
portion
113.
Typically, the riser 402 and BOP 502 equipment installed at this stage has an
inner
diameter that is sufficiently large to retrieve the tubing hanger 116 there
through. In
many cases, the tubing hanger 116 is of a substantially larger outer diameter
than the
tubing 108 itself.
Figure 5 illustrates the situation after the riser 402 and BOP 502 system has
been
stacked in place, but where the shallow set barrier 401 shown in fig. 4 has
been
io removed. For the illustrated embodiment, the upper stack contains
various modules
that are bolted together using bolt connections 501, 501', 501". On top of the
riser
402, a BOP valve 502 is mounted. This BOP valve 502 could be a shear ram. In
other
embodiments, alternative or additional valve/ram systems could be added, such
as
pipe rams and blind rams. This would be appreciated by a person skilled in the
art. On
top of the BOP valve 502 a second riser 503 section, a wireline crossover 504
and a
grease injection 505 head are mounted.
The next step in the process of pulling the tubing 108 is to remove the tubing
hanger
116 from the well 100. A wireline 507 deployed cutting tool 506 is run in the
well to
cut the tubing 108 below the tubing hanger 116. Typically, the cut would be
placed
close to a clamp (not illustrated) used to secure the control line 110 to the
tubing 108
to ensure that the control line is cut as well. The well operation deck level,
often
referred to as the hatch deck 508 is also illustrated.
Now considering fig. 6; after the tubing 108 and control line 110 has been
cut, the
cutting tool 506 is retrieved, and a pulling tool 601 for the tubing hanger
116 is run in
the well 100 and engaged to the tubing hanger 116. Subsequent to this, the
tubing
hanger 116 is released, typically by unscrewing bolts (not illustrated) that
secures the
tubing hanger 116 to the intermediate unihead portion 113. Upon doing so, the
tubing
hanger 116 can be pulled up into the second riser 503, whereupon the BOP valve
502
is closed. This is illustrated in fig. 7.
Subsequently, the second riser 503 can be disconnected from the BOP valve 502
and
the tubular segment containing the tubing hanger 116 can be removed.
In some cases, the tubing hanger 116 may be partly stuck inside the
intermediate
unihead portion 113, to a degree where traditional wireline cable 507 cannot
be used
to pull it. Instead, a stronger cable may be used, a solid steel rod or other
system for
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pulling the tubing hanger 116 loose. To provide for sufficient force tailor
made jack
systems that are suspended from the top of the riser stack could be utilized.
Alternatively, other devices capable of creating high push and/or pull forces
could be
used. This would be appreciated by a person skilled in the art and is no
further
referred to herein.
Now considering fig. 8; after removing the tubing hanger 116, further to a
preferred
embodiment of the invention, some of the larger bore well control sections
such as the
second riser 503 would be removed, as this is over-dimensioned for tubing 108
pulling
purposes. Instead, a smaller wireline lubricator stack could be applied for
the
subsequent operations. The wireline lubricator stack would in one embodiment
include
riser sections 801, 801' and a wireline BOP unit 802. Other system components
could
also be included, but are omitted from the figure for simplicity. The
inclusion of such
components would be appreciated by a person skilled in the art.
As illustrated in fig. 9, a working platform 901 for personnel and a wireline
rig-up mast
902 are typically mounted adjacent to the wireline lubricator prior to
commencing the
tubing 108 retrieval operation. Normally, the wireline mast 902 will be the
main
support for a top sheave wheel that the wireline cable 507 is run over when
intervening tools in the well. In a preferred embodiment of the invention, the
wireline
mast 902 will in this context be utilized for the tubing 108 retrieval
operation.
As a last explanatory step before describing the core method of the invention
herein;
fig. 10 describes additional support systems that may be used for lifting and
pipe
handling operations. On platforms where the drilling rig has been demobilized,
skid
beams 1001 are normally not removed. In a preferred embodiment of the
invention, a
modular traverse-crane 1002 or other mobile crane system suited to be mounted
and
operated on the skid beams 1001 forms part of the mobilized equipment package.
Moreover, a tailored pipe handling mast system 1003 could form part of the
package.
In a preferred embodiment, both crane/mast systems can be lifted onboard the
platform and mounted in place using the platform crane. A traverse-crane 1002
is
normally the preferred option when rigging up well control equipment such as
risers,
BOPs etc. as it is more accurate and less impacted by forces such as wind
forces than
a platform crane, i.e. it makes the operation safer for both personnel and
equipment.
Fig. 11 illustrates a section of the well 100 of consideration. In a previous
step, the
tubing 108 has been cut, as illustrated by the line A-A', and the section of
tubing 108
above the cut has been pulled out of the well 100. In the embodiment shown,
the
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tubing 108 and the annulus between the tubing 108 and the casing 107 are
filled with
a heavy liquid 1101 such as brine or drilling mud.
Now considering fig. 12; a cutting tool 506 is used to create a new cut B-B`
at a
location below cut A-A'. By means, an isolated tubing segment 1201 having a
first end
portion A-A' and a second end portion B-B' has been created. The length of the
tubing
section 1201 may vary, depending on well conditions as well as operational
constraints. However, in a preferred embodiment of the invention, the length
of the
tubing section 1201 is longer than what is practical to pull using traditional
wireline (or
alternative) methods, i.e. without using the system of this invention.
The cutting tool 506 may be of a mechanical, pyrotechnical, explosive,
chemical or
other nature. Such aspects would be appreciated by a person skilled in the art
and is
no further referred to herein.
Now considering fig. 13; here a deep set barrier 1301, such as a mechanical
plug
comprising a check valve, is installed in a lower portion of the tubing
segment 1201.
However, in one embodiment of the invention, the barrier 1301 is not required
for the
tubing 108 pulling operation but is illustrated herein merely to emphasize
this
operational possibility.
Fig. 14 illustrates a retrieval apparatus according to the present invention
in the form
of a tubing retrieval module 1401 being engaged to the tubing segment 1201.
The
tubing retrieval module 1401 comprises a guide nose 1402 for proper entering
into the
tubing segment 1201, an engagement means in the form of an anchoring module
1403, a sealing means in the form of a seal module 1404 for sealing off a top
section
of the tubing segment 1201, a control module 1405 and a termination module
1406
where the wireline cable 507 and/or hydraulic line 1407 and/or coil tubing
(see fig.
23) are terminated. In one embodiment (not shown) of the invention, the tubing
retrieval module 1401 is split into two or more separate modules that are
independently run and operated in the well. Such separate modules may for
example
be the seal module 1404, the injection means, and retrieval module 1401 with
the
anchoring module 1403.
In the embodiment shown in fig. 14, the tubing retrieval module 1401 is
engaged in a
top portion of the tubing 1201. However, it should be noted that the tubing
retrieval
module may be engaged anywhere between the first or upper end portion A-A' and
the second or lower end portion B-B' of the tubing 1201, as illustrated in
fig. 27.
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In fig. 14 the tubing retrieval module 1401 is run on a combined cable 507 and
hydraulic line 1407. However, such a setup may not be desirable due to the
risk of the
toolstring spinning in the well (hence tangling the cable 507 and hydraulic
line 1407
into each other), due to complexity in the surface rig-up, due to difficulties
in
matching pulling speed and tension between the two line types as well as other
factors. In an alternative embodiment, a novel intervention cable is developed
and
used, that incorporates one or more hydraulic lines inside the cable body. In
one
associated embodiment, the externals of such a cable resemble cable types that
are
used for well intervention today. In one embodiment, such a novel cable
features a
combination of external strands (to provide for mechanical strength) and a
hydraulic
communication line only. In other embodiments, electric or fiber optic lines
may be
included in the cable design, to provide for more options with respect to
operation of
the control module 1405.
In an alternative embodiment, the tubing retrieval module 1401 is run and
operated
on coil tubing, snubbing pipe or drill pipe. In particular, a coil tubing
deployed
operation may provide for an attractive operational scenario, as coil tubing
may also
be used for subsequent cementing operations, hence there is an overlap in
equipment
requirements in this respect.
The engagement of the anchor 1403 to the tubing segment 1201 may be in the
form
of a design for automatic engagement, or the engagement may be controlled in
form
of operator controlled or pre-programmed actions using the control module
1405.
Similar considerations apply for the seal module 1404.
Fig. 15 illustrates a key step according to the present invention where a top
portion of
the tubing segment 1201 is filled with a low density fluid in the form of gas
1501 such
as for example, but not limited to, nitrogen or other suitable gases. As
mentioned in
the general part of the specification; although a low density fluid in the
form of a gas
1501 is preferred for increasing the buoyancy of the tubing 1201, the low
density fluid
may also be a liquid having a lower density than the heavy liquid 1101 to be
replaced.
Thus, a condensate or even water may be used, for example. However, in the
description below the low density fluid will be referred to as gas 1501, but
should not
exclude other appropriate fluids having a density lower than the heavy liquid
1101 to
be replaced.
In the embodiment shown in fig. 15, the gas 1501 is routed from the surface
down the
hydraulic line 1407. In a preferred embodiment, the gas 1501 is introduced
into the
tubing segment 1201 at a pressure that exceeds the hydrostatic pressure in
that
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section of the well 100. This will cause the gas 1501 to displace the heavy
liquid 1101
out of the tubing segment 1201 via the check valve of the deep set barrier
1301, as
illustrated by the arrows in fig. 15. For an embodiment where no barrier 1301
is pre-
installed, the heavy liquid 1101 will be displaced in an equivalent manner,
provided
that the tubing segment 1201 is oriented substantially vertically, i.e. with
the
apparatus 1401 according to the present invention being above the second end
portion B-B' of the tubing 1201. For a horizontal alignment, the method would
not be
suitable unless having a pre-installed barrier 1301 and a check valve system
that
allowed for bleeding out the fluids prior to letting out the gas. As an
example; in a
horizontal configuration, the check valve of the barrier 1301 could be
designed in an
off-center fashion and allowed to freely rotate around the center axis of the
barrier
1301. Moreover, the check valve could be provided with or surrounded by a
heavy
material that would tend to bias the freely rotating check valve towards the
lower
lying side of the tubing segment 1201 in order to primarily drain out heavy
liquid
when letting gas 1501 or low density liquids into the tubing segment 1201 as
illustrated in fig. 15.
In one embodiment of the invention, the gas 1501 is routed straight through
the
control module 1405, i.e. the control module 1405 would in such cases feature
an
open design. In other embodiments the control module 1405 could be designed to
perform more sophisticated tasks such as activating the anchors 1403 and/or
the seal
1404 prior to routing high pressure gas 1501 into the tubing segment 1201.
The operation of the control module 1405 could be in the form of an electric
or fiber
optic operation, or by hydraulic operation such as manipulation of valves set
to
operate at different pressure. In another embodiment, mechanic counter devices
and/or wireless techniques could form part of a control system. In one
embodiment of
the invention, the operation of the control module 1405 could be in the form
of
combination of the above methods. In one embodiment, multiple hydraulic lines
are
deployed into the well as part of the intervention equipment, and the control
module
1401 could then be operated in the form of manipulating pressure via such
multiple
deployed lines. Such aspects of the operation would be appreciated by a person
skilled
in the art and is no further referred to herein.
Figure 16 illustrates retrieval of the tubing segment 1201 from its original
position in
the well 100. As the tubing segment 1201 is moved upward in the well 100
during
retrieval, the surrounding hydrostatic pressure would decrease. This will
cause
expansion of the gas 1501, and displace the remaining liquid 1101 through the
check
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valve of barrier 1301. This again would entail gas bubbles 1601 trickling
through the
liquid 1101 towards the top of the well. For such a method a pressure control
apparatus would typically be installed on the surface to capture the gas and
vent it off
in a controllable fashion.
In a preferred embodiment of the invention, as the tubing segment 1201 is
retrieved
from the well 100 and the surrounding pressure decreases, gas is bled off by
means of
taking return up the control line 1407, or up the coil tubing 2301 (see fig.
23) if coil
tubing is utilized for the operation. By means, this would eliminate or reduce
the
amount of free gas that would be released in the liquid 1101. Moreover, this
could
help limit the buoyancy force that acts on the tubing segment 1201. If the
buoyancy
force gets sufficiently large, which could be the case if the liquid 1101 is
heavy and
the pressure of gas 1501 is low, the tubing segment 1201 could float, and this
is
generally unwanted as it makes the operation of retrieving the tubing segment
1201
less controllable. In one embodiment of the invention, heavier liquids are
pumped
down the control line 1407 (alternatively the coil tubing 2301) or let into
the tubing
segment 1201 from the surroundings, during the retrieval operation to reduce
the
buoyancy force as a function of pulling the tubing segment 1201 out of the
well. In
another embodiment, as shown in fig. 27, the retrieval module 1401 including
seal
module 1404 is installed in a portion of the tubing segment 1201 away from the
first
end portion A-A' as will be discussed below.
If running the system on coil tubing 2301 (see fig. 23), there is a general
requirement
that there should be check valves in the lower portion of the coil tubing
(close to the
toolstring of relevance). This could prevent the return of gas from the tubing
segment
1201 to the surface, and is part of a controlled retrieval operation. In one
embodiment
of the invention, one or more of the barrier 1301 with check valve built-in,
would with
respect to functionality replace the need for including check valves in the
coil tubing
itself.
In a preferred embodiment of the invention the control module 1405 is equipped
with
sensors (not shown) known per se that help detecting the status such as gas
pressure
inside and outside the tubing segment 1201, as well as other relevant sensor
systems
also known per se for monitoring acceleration, motion, velocity and similar,
to provide
diagnostics data that could form the basis for an intelligent/controlled
buoyancy force
balancing operation. Temperature effects will also have an impact on the gas
density
at a given pressure. In one embodiment of the invention, the control module
1405
includes a temperature sensor to monitor and provide for the compensation for
such
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effects. In one embodiment the control module 1405 is equipped with valves for
automatically and/or manually bleeding off pressure inside the tubing segment
1201
should this become too high. In particular, when the equipment is located at
the top of
the well, prior to starting the part of the tubing retrieval process that
takes place on
the surface, all gas pressure must be bleed out of the system to avoid
personnel
and/or equipment being exposed to high gas pressure.
In one embodiment the control module 1405 is equipped with valves (not shown)
for
letting surrounding fluids into the pipe segment 1201. In another embodiment,
the
control module 1405 is equipped with valves that provides for a controlled
routing of
liquids from the surface, via the control line 1407 or coil tubing if that is
being used for
the operation. In one embodiment, such valves are the same valves initially
used for
routing gas into the tubing segment 1201.
In one embodiment, the control module 1405 can be addressed to activate brake
pads
or similar to stop unwanted and/or uncontrolled upwards motion of the string
due to
buoyancy effects. In an associated embodiment, the control module 1405
includes
measures for a controlled emergency disconnect function.
Fig. 17 illustrates parts of the surface pressure control equipment for the
embodiment
involving a cable 507 combined with a hydraulic line 1407 operation. Here, a
control
line spool 1701 is added to the pressure control equipment stack to facilitate
for
running the line 1407. Added features such as BOP equivalent valves may be
required.
This would be appreciated by a person skilled in the art and no further
referred to
herein. As explained in relation to fig. 14; such a setup may not be
desirable. In the
future, wireline cables that incorporate a hydraulic line may be made for such
purposes. In the short term, the deployment and operation of the tubing
retrieval
system on coil tubing may prove to be equivalently or more attractive than the
scenario illustrated in fig. 14 where a cable 507 and a hydraulic line 1407 is
run side-
by-side.
Fig. 17 also illustrates a fluid line 1702 used to fill additional fluid into
the well 100 as
the tubing section 1201 is retrieved, and to kill the well in the case of
emergency. In
real life operations, additional lines may be used to create a circulation
envelope. This
would be appreciated by a person skilled in the art. Moreover, a pressure
control stack
may include one or more bleed-off line(s) 1703 used to bleed off gas 1501
pressure
should free gas 1501 be released to the well fluid 1101 during the operation.
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Fig. 18 illustrates a first step of physical disassembly and removal of the
tubing
segment 1201 when this has reached the surface. In fig. 18, the control line
spool
1701 and the grease injection head 505 has been taken off the pressure control
stack,
and a bushing 1801 to facilitate the alternating use of pipe slips 1802 has
been
mounted. Further details related to systems and methods for mounting and
operating
these modules would be appreciated by a person skilled in the art and is not
described
herein.
For the embodiment illustrated in fig. 18, the control module 1405 and a
termination
module 1406 of the tubing retrieval tool 1401 has been removed, and the tubing
segment 1201 is hung off in slips 1802. Subsequent to this, the anchoring
module
1403, the seal module 1404 and the guide nose 1402 is removed.
Fig. 19 illustrates a lifting device such as a ball grab 1901 being connected
to the top
of the tubing segment 1201 and lifting this out of the well 100. For this
lifting
operation, the wireline mast 901 of fig. 9 or the traverse-crane 1002 of fig.
10 could
be utilized.
Subsequently, the tubing segment 1201 is cut at an appropriate distance from
the top,
illustrated by the line C-C', whereupon the cut tubing piece is removed and
laid down
on a deck of the rig. For this purpose, a pipe handling mast 1003 as
illustrated in fig.
10 could be used. Various techniques could be used to create the cut C-C',
including
but not limited to abrasive water cutters, wire cutters and blade cutters.
This would be
appreciated by a person skilled in the art.
The process is then repeated until the entire tubing segment 1201 has been
retrieved
hence removed from the well.
Fig. 20 illustrates a situation where settled material 2001 such as for
example barite,
or other conditions have made the tubing segment 1201 stuck in the well. In
fig. 20,
the tubing retrieval tool 1401 has been disconnected above the control module
1405.
In a preferred embodiment of the invention, it is possible to perform
controlled system
disconnects. Moreover, in a preferred embodiment of the invention, a
disconnect
operation would leave a fresh engagement profile and seal surfaces inside or
outside
the top module that is left in the well for re-engagement and continuation of
the
operation at a later stage with heavier equipment such as coil tubing,
snubbing pipe or
drill pipe.
Fig. 21 illustrates a method for releasing a stuck tubing segment 1201 further
to the
case illustrated in fig. 20, where high pressure gas or liquid is routed into
the tubing
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segment 1201 as per previously described procedure(s). The aim is to create
fluid
circulation through the column of settled barite 2001 or similar, so that this
will soften
and/or erode or flow away, and thereby release the tubing segment 1201. Thus
the
apparatus 1401 according to the present invention is utilized for releasing a
stuck
tubing segment 1201. Alternatively a downhole jack system as described in the
general part of this document could be used to operate/work the tubing segment
1201
loose prior to pulling it out of the hole using techniques as defined by the
invention
herein. Similar means could be applied to tear off uncut control lines, or to
overcome
forces required to split the tubing should the process to make the cut B-B' be
only
partly successful.
In one embodiment of the present invention, high pressurized gas for filling
at least
parts of the tubing segment 1201 is deployed into the well as part of the
wireline
toolstring. In the embodiment shown in fig. 22, the gas is contained in a high
pressure
flask 2201 or similar deployed into the well 100. Do note that in this case
the
hydraulic control 1407 line to surface can be omitted, and the operation
conducted on
wireline 507 only.
In another embodiment of the invention (not shown), the gas is created locally
by
burning a similar type of power charges that are used in setting tools for
downhole
plug setting, mix certain chemicals, or expose certain chemicals to certain
solids, as
will be appreciated by a person skilled in the art
Fig. 23 illustrates the operation conducted on coil tubing 2301. A benefit
here is that
coil tubing is capable of applying higher operative force (pull/push) than
wireline 507,
and that the need for a dual line operation such as the combined wireline 507
and
hydraulic line 1407 illustrated in the previous figures, is removed.
Fig. 24 illustrates the operation conducted on a special wireline 2401
containing a
hydraulic line inside it. Fig. 25a and fig. 25b illustrate cross sectional
views for two
versions of such special wireline 2401. Fig 25a illustrates a hydraulic centre
pipe 2501,
covered by a bonding layer 2502 and an outer layer of wire strands 2503. The
bonding
layer 2502 could be included to create necessary friction between the centre
pipe
2501 and the strands 2503. In other embodiments, there could be multiple
strand
2503 layers, or the strands 2503 could be embedded into an outer layer 2504
made of
polymer or similar to provide for a slick purpose and remove the need for a
grease
injection head (i.e. this could be replaced with a simpler design packer based
seal). An
example of such is illustrated in fig. 25b. Fig. 25b also illustrates an
electric lead 2505
embedded in the cable. In general, all known methods for cable manufacturing
that
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includes one or more hydraulic conduits within the framework of the cable
could be
utilized for such purposes. This will be appreciated by a person skilled in
the art.
With reference to fig. 26; in one embodiment of the invention, a smaller
portion of
high pressurized gas is placed in the top section of the tubing segment 1201
(by any
means described herein), whereupon a pump (not shown) inside the tubing
retrieval
tool 1401 is used to pump fluid out of the isolated tubing segment 1201
between the
barrier 1301 and the tubing retrieval tool 1401 via a straw system 2601 and
into the
surroundings. In the embodiment illustrated in fig. 26, a defined portion of
gas 1501 is
let into the tubing segment 1201 via gas injection means exiting via gas
nozzles 2602.
Subsequent to this, a pump (not illustrated) located somewhere in the wireline
toolstring is used to suck/pump liquid out of the bottom portion of the tubing
segment
1201 via an inlet 2603 of the straw 2601. The fluids flows from said inlet via
internal
conduits of the straw 2601 to a liquid outlet 2604 located outside the tubing
segment
1201. By means, as liquid is removed from the tubing segment 1201, the
pressure
decreases, whereupon the gas 1501 portion increases in size and - ultimately -
the
buoyancy force acting on the tubing segment 1201 increases.
The benefit of the apparatus illustrated in fig. 26 is that it provides for a
possibility to
fill a substantial part of the tubing segment 1201 with gas despite only being
able to
deploy a relatively low/modest amount of high pressure gas into the well as
part of
the tool string. Moreover, such an operation would entail the placement of a
relatively
large gas portion inside tubing segment 1201 that is of a lower pressure than
the
surrounding pressure; hence the density of the gas would be less than would be
the
case if the gas was to be pressurized to equal the surroundings. In the case
of placing
a low pressure gas column inside the tubing section 1201, the buoyancy force
would
be higher than for the equal pressure case, which could be beneficial for the
operation.
In fig. 27 the retrieval module 1401 including seal module 1404 is not
installed in a
top portion of the tubing segment 1201 as illustrated for example in fig. 14,
but at a
location further down the tubing segment 1201, as mentioned above. The
intention
with such an arrangement is to avoid filling the entire tubing segment 1201
substantially defined by the first end portion A-A' and the second end portion
B-B' with
gas 1501 as illustrated in fig. 16, hence risk the tubing segment 1201 being
exposed
to a net upwards force due to buoyancy during certain stages of the retrieval
process.
By means, for this method only a portion of the tubing segment 1201 can be
filled
with gas.
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In fig. 27 a gas injections means in the form of a gas injection manifold 2702
is also
illustrated. Such a gas injection manifold 2702 may also be provided in the
apparatus
shown in for example figures 14-16. Gas 1501 (see fig. 15) supplied from the
surface
via the line 1407 flows via the gas injection manifold 2702 and out of the
guide nose
1402 as illustrated by the dotted line 2701.
In fig. 28 the apparatus is provided with an inflatable bladder 2801 that
replaces the
liquid 1101 in the tubing 1201 as gas 1501 is injected into the bladder 2801
by means
of the gas injection means. In the embodiment shown the bladder 2801 is
arranged at
an end portion of the guide nose 1402 and separate from the seal module 1404.
However, as the bladder 2801 itself provides a sealing means, the seal module
1404
may be omitted. The bladder 2801 will keep the gas separate from the liquid
1101. In
the embodiment shown in fig. 28 the bladder 2801 is arranged at an elevation
lower
than the anchor module 1403. However, the bladder 2801 may in an alternative
embodiment (not shown) be arranged at an elevation above the anchor module
1403.
In a preferred embodiment, the method and the apparatus according to the
present
invention is used to retrieve tubular 1201 from a subsea well 100 using a
light weight
intervention vessel (RLWI vessel). Further to a preferred embodiment, tubing
1201
from a subsea well 100 is retrieved to the surface in lengths that equals the
sea depth
above the wellhead, minus operational margins as defined by the vessel and the
pressure control equipment plus safety margins. Moreover, further to the same
embodiment, rather than pulling the tubing 1201 to the vessel, the tubing 1201
is
transferred to a secondary vessel dedicated for disposal of the tubing. In one
embodiment, the transfer system yields making a connection to the top portion
of the
tubing with a wire or similar run from the secondary vessel prior to
performing a
controlled disconnect from the cut tubing from the wire suspended from the
intervention vessel. By means, the process of pulling tubing from subsea wells
can
now be optimized, using wireline intervention vessels for the downhole
operations, but
secondary vessels for the pipe handling. This way, sophisticated intervention
vessels
do not need upgrading for pipe handling, which would be a very costly
exercise. The
secondary vessel could in one embodiment disassemble the cut tubing pieces
locally.
In another embodiment, the secondary vessel would tow the cut tubing segments
to a
location closer to land, where purpose built handling systems could perform
the final
breakdown operations on the tubing in a more cost effective manner.
